Conventionally, when a wellbore is created, a number of casings are installed in the borehole to prevent collapse of the borehole wall and to prevent undesired outflow of drilling fluid into the formation or inflow of fluid from the formation into the borehole. The borehole is typically drilled in intervals whereby a casing (such as, steel pipe), which is to be installed in a lower borehole interval, is lowered through a previously installed casing of an upper borehole interval. As a consequence of this procedure, the casing of the lower interval is of smaller diameter than the casing of the upper interval. Thus, the casings are in a nested arrangement with casing diameters decreasing in the downward direction. Cement annuli are provided between the outer surfaces of the casings and the borehole wall to seal the casings from the borehole wall.
As a consequence of this nested arrangement, relatively large borehole diameters are required in the upper part of the wellbore. Such large borehole diameters involve increased costs due to the time to drill the holes, the time to install all of the casings, costs of casing, drilling fluid consumption. Moreover, increased drilling rig time and costs are involved due to required cement pumping, cement hardening, required equipment changes due to variations in hole diameters drilled in the course of the well, and the large volume of cuttings drilled and removed.
In most wells, the most critical role of the casing/cementing system is to increase the minimum fracture gradient to enable continued drilling. Generally, when drilling a well, the pore pressure gradient (PPG) and the fracture pressure gradient (FG) increase with the true vertical depth (TVD) of the well. For each drilling interval, a mud density (mud weight or MW) is used that is greater than the pore pressure gradient, but less than the fracture pressure gradient. As the well is deepened, the mud weight is increased to maintain a safe margin above the pore pressure gradient. If the mud weight were to fall below the pore pressure gradient, the well may take a kick. A kick is an influx of formation fluid into the wellbore. Kicks can result in dangerous situations and extra well costs to regain control of the well. If the mud weight is increased too much, the mud weight will exceed the fracture pressure gradient at the top of the drilling interval (usually this is the location with the smallest fracture pressure gradient). This normally leads to lost returns. Typically, lost returns occurs when the drilling fluid flows into a fracture (or other opening) created in the formation. Lost returns results in the cuttings not being removed from the wellbore. The cuttings may then accumulate around the drill string causing the drill string to become stuck. Stuck drill pipe is a difficult and costly problem that often results in abandoning the interval or the entire well.
To prevent the above situation from occurring, conventional practice typically involves running and cementing a steel casing string in the well. The casing and cement serve to block the pathway for the mud pressure to be applied to the earth above the depth of the casing shoe. This allows the mud weight to be increased so that the next drilling interval can be drilled. This process is generally repeated using decreasing bit and casing sizes until the well reaches the planned depth. The process of tripping, running casing, and cementing may account for as much as 25 to 65 percent of the time required for drilling a well. Tripping is the process of pulling the drill pipe or running the drill pipe into the well. This is important, because well costs are primarily driven by the rig time required to construct the well. Furthermore, with the conventional steel casing tapered-hole-drilling process, the final hole size that is achieved may not be useable or optimal and the casing and cement operations substantially increase well costs.
For exploration wells, the reduction in hole size with increasing depth may result in not reaching the planned target depth or not reaching the planned target depth with enough hole size to run logging tools to fully evaluate the formation. Typically, at least a 0.1524 meter (6-inch) open hole is needed to fully evaluate the formation. For some wells, the need to set casing to accommodate pore pressure/fracture gradient concerns results in running out of hole size. For development wells, the telescopic nature of the well reduces the final hole size in the reservoir. This reduction in contact of the well with the reservoir may reduce the production rate of the well, thereby, reducing the well's performance. Generally, a larger hole size in the reservoir increases the well's production rate for a given drawdown. Drawdown is the difference between the fluid pressure in the reservoir and inside the well.
Current technology to address the problems discussed above include the use of solid expandable liners (SELs). An example of a solid expandable liner is disclosed in U.S. Pat. No. 6,497,289. Solid expandable liners are special tubular systems that are run into a well and then expanded. The expansion allows the open hole to be lined using a string that has a larger interior diameter than would otherwise be available with a conventional liner. The solid expandable liner system allows a larger bit and/or additional casing strings to be run in the well. This facilitates penetrating the reservoir with a larger hole size in development wells. For exploration wells, having one or two additional liners may enable the well to reach a planned target or deeper with a useable hole size.
While a solid expandable liner may be beneficial, it has several drawbacks. These include time and cost, connections, hole quality requirements, tapering, and cementing. Some of the drawbacks of solid expandable liners are summarized in the following paragraphs.
The process of installing a solid expandable liner takes longer than a conventional liner. This is because solid expandable liners must be expanded. Also, installing a solid expandable liner may require considerable time because the string must be run into the well very slowly due to the surge pressure created by the small-clearance expansion cone assembly. The additional time, as well as the direct cost of the solid expandable liner, makes solid expandable liners much more costly than a conventional liner.
A solid expandable liner uses special connections that are expanded along with the pipe body. The expansion may reduce the sealing and/or tensile capacity of the connections. At least one example of failure of a solid expandable liner connector has been documented in “Solid Expandable Tubular Technology—A Year of Case Histories in the Drilling Environment,” Dupal, et al., SPE/IADC Drilling Conference held in Amsterdam, The Netherlands, 27 Feb.-1 Mar. 2001, Paper SPE/IADC 67770.
If the hole is not straight, but contains doglegs (kinks) or other imperfections, or if the solid expandable liner is differentially stuck, the expansion cone may become stuck. An example of this type of problem has also been documented in “Solid Expandable Tubular Technology—A Year of Case Histories in the Drilling Environment,” Dupal, et al., SPE/IADC Drilling Conference held in Amsterdam, The Netherlands, 27 Feb.-1 Mar. 2001, Paper SPE/IADC 67770.
The currently available solid expandable liner system still results in a tapered wellbore. This is a fundamental problem because the expansion cone carrier assembly must pass through the previous liner.
With currently available solid expandable liners, the cement is placed around the liner or casing prior to expansion. If there is a malfunction during expansion, it is unlikely that the liner could be removed from the well for repair or replacement.
Another approach to mitigate the problem of having to periodically run casing, especially in deepwater wells, is to use a dual (or multiple) gradient drilling system. For example, U.S. Pat. No. 4,099,583 discloses a dual gradient drilling system. In this method, a lighter fluid is injected into the mud return annulus (typically in the riser) or other pathway to reduce the mud density from the injection point upwards. This helps tailor the mud pressure gradient profile to closer match the desired pressure gradient profile that is between the pore pressure gradient and fracture gradient profiles. Multiple gradient drilling systems may reduce the required number of casing strings by possibly one or two. However, these systems are mechanically complex, are very costly to implement, create operational concerns (for example, for well control), and still result in a tapered wellbore.
A “method for centrifugally forming a subterranean soil-cement casing” is disclosed in U.S. Pat. No. 6,183,166. In this method, a soil-processing tool is advanced and rotated into the earth while high velocity cement slurry is introduced to mix with the soil. As the device is withdrawn, the tool is rotated at a speed to exert a centrifugal force on the soil-cement mixture, causing the mixture to form a soil-cement casing at the outer region of the hole. Unfortunately, drawbacks to this soil-cement casing technique include that the soil-cement casing is weak and this technique does not avoid tapering.
Accordingly, there is a need for an improved system to install casings or linings inside wellbores that addresses the above-mentioned drawbacks of current casing techniques. This invention satisfies that need.